Method for removing noncombustibles from fuel gas



Sept. 7, 1948. J. w. LA TCHUM, JR

METHOD FOR REMOVING NONCOHBUSTIBLES FROM FUEL GAS Filed Dec. 18, 1944 .wuwigmgg. ATTORNEM 2. r mo 5 R s ,m m v m g V S S m w 1N2 no M H 8 B on MM 3 a 2: mm v I El Ia m m h mm. om; A .5 IM t. Z v V 0T w a: mu. u. o u ln. a u sz nv. "I 2.

- Patented Sept. 1, 194s 2,448,719

METHOD FOR REMOVING NONCOM- BUSTIBLES FROM GAS John W. Latclmm,.Jr., Bartlesville, Okla... asslgnor to Phillips Petroleum Company, a corporation of Delaware Application December 18, 1944, Serial No. 568,766

17 Claims. (Cl. 23-3) This invention relates to a treatment of fuel gases. In one of its more specific aspects it relates 'to a method and to apparatus for the removal of nitrogen from natural hydrocarbon gases containing this inert gas in objectionable proportions. In another specific aspect it relates to a method and to apparatus for removing nitrogen, oxygen, argon, helium and neon from artificial fuel gases, such as water gas, producer gas, blau gas or others. transporting, say 50,000,000 cubic feet per day As the removal of nitrogen from natural gas is of a gas containing as much as by volume of by far the bigger field at present, the example nitrogen through a long pipeline, the operation chosen for illustrative purposes is natural gas, involves repeated compression of7,500,000 cubic but it should be'remembered any usual fuel gas feet of the inert gas and the construction of the may be thereby separated from nitrogen, and the 15 pipeline with a 15 per cent greater capacity than term nitrogen is intended herein to include oxyif the impurity were not present. The cost of gen, argon, helium, neon, krypton, xenon and such compressions may amount to hundreds of carbon dioxide. Whether neon. krypton, xenon, thousands of dollars per year. The additional and even argon are removed or not is generally capital cost of the pipeline and compression immaterial as they are usually only present in equipment for a long line may, on the other hand,

small amounts.

As natural gas comes from the earth, it frequently and in fact usually contains other gases in addition to the hydrocarbons. Occasionally, however, a well is drilled which produces largely carbon dioxide, others have been "brought in as gas wells, the gas' from which contains largely nitrogen. In most instances gases produced from wells are mixtures of many different and frequently unlike gases. A well known as a carbon dioxide well may produce in addition oxygen, nitrogen and even hydrogen sulfide. In a similar manner, nitrogen wells usually do not produce only nitrogen. Hydrocarbon producing wells are no exception to this rule and they usually produce impure natural gas" with respect to the hydrocarbon content. These gases sometimes contain traces of oxygen. some hydrogen sulfide and mercaptan type compounds, some carbon dioxide and nitrogen. The amounts orproportions of these impurities vary widely. Some gases contain several percent of such materials, and a gas produced, at One time in South Central Kansas contained such a large proportion of nitrogen that it burned only by the continuous application of a torch. This gas also contained 1.84% helium.

A natural gas containing as much as 10 to 20% impurity presents serious considerations when marketing is contemplated. The presence of carbon dioxide and/or nitrogen lowers the heating value of a gas merely by their presence (dilution effect) while hydrogen sulfide and/or mercaptans cause the gas to be corrosive and to possess a foul odor. Combustion products 01' sulfur compounds possess a disagreeable odor as well as being corrosive, especially when moist. The removal of hydrogen sulfide type of compounds from natural gas to be used in domestic heating. process work or metallurgical work is imperative.

Transportation of a natural gas containing much nitrogen or carbon dioxide by pipelinepresents economic problems. For example, when be greater than the cost of a plant to remove the nitrogen.

In addition, the dilution effect of nitrogen and carbon dioxide lowers the heating value of a gas, or conversely, a gas containing one or both of these inert impurities may be upgraded merely by their removal. For example, a gas having a calorific value of 1000 B. t.u. per cubic foot and containing 15 per cent by volume of nitrogen will have a heating value of 1,150 B. t. u. upon removal of this nitrogen. Then also, a gas of this latter heating value can yield a considerable quantity of gasoline hydrocarbons and yet maintain a heating value of 1000 B. t. u.

I have devised a unitary, continuous process for treating such a hydrocarbon gas whereby substantially all of the nitrogen impurity is removed. The gas which I propose to treat by this process contains 15% by volume of nitrogen, some hydrogen sulfide sourness and a trace of moisture.

An object of my invention is to provide a process for the removal of relatively large amounts of free nitrogen from natural gas.

Anothervobject of my invention is to provide a process for the removal of nitrogen from natural gas so that pipeline transportation of the gas may be carried out more economically.

Still another object of my invention is to provide a process not involving excessively high pressures nor costly low temperatures for the removal of nitrogen from natural gas.

Still other objects and advantages of my process will be apparent to those skilled in such art from a careful study of the following disclosure.

The accompanying drawing forming a part of this disclosure illustrates diagrammatically one form of apparatus in which the process of my invention may be practiced.

Referring to the drawing, raw natural gas to be treated mainly for removal of its gaseous nitrogen content enters my treating system through a line H directly from. a production field or from an intermediate storage, not shown. For exemplary purposes, I will assume the gas to enter my treating system at an inlet pressure of approximately 720 pounds per square inch absolute. and

' at a temperature of from 90 to 100 F., that is,

slightly above atmospheric. The gas will also be assumed to contain a very small amount of hydrogen sulfide soumess, a small amount of moisture and a usual proportion of condensible hydrocarbons such as those easily extractable and normally contained in natural gasoline. In addition to these impurities and heavier than gas hydrocarbons, the gas is assumed to contain about 15% by volume of gaseous nitrogen.

While the gas, as mentioned above, may conmm 1128, moisture and gasoline hydrocarbons, it may also be free of any or all of these constituents and yet be successfully treated by the process herein disclosed. For exemplary purposes I will assume all parts and units of my system to be explained and described hereinafter to be of sufficient size and capacity as to permit processing of 50 million standard cubic feet raw gas per day of 24 hours.

For purposes of description and for being consistent throughout, all temperatures stated will be in degrees Fahrenheit, and all pressures will be in pounds per square inch absolute, unless, of course, otherwise specified.

The gas to be treated passes from the inlet line I I directly into a main absorption column II at a point near its bottom. Liquid absorbent sulfur dioxide enters the column through a lean absorbent line i 3 at a point near the top thereof. The absorbent enters the column under the treating pressure of about 720 pounds per square inch and at a temperature of from 90 to 100 F., and flows downwardly by gravity in countercurrent relation to upward flowing gas being treated. At this temperature and pressure substantially all of the gaseous nitrogen becomes dissolved in or absorbed by the liquid sulfur dioxide. This absorbent has an appreciable vapor pressure even in the region of 700 pounds total pressure and accordingly the treated nitrogen-free gas leaving the absorber through a treated gas outlet line l8 contains a considerable proportion of sulfur dioxide gas. Under normal operating conditions, this proportion amounts to from about 6 to 10% by volume of the treated gas.

To minimize this S02 carryout in the treated gas I provide a cooling coil It in the upper portion of the absorber vessel I2; and contrary to conventional absorber construction, I provide the heating coil II, as mentioned hereinafter. The cooling coil may be cooled by circulation of refrigerant therethrough, the refrigerant, may if desired, be a portion of that circulated through the cooling coil 6! of desorber 51. It is necessary to cool the top of the absorber II to lower the partial pressure of the sulfur dioxide solvent and accordingly lower the amount carried out by the treated gases. in an attempt to lighten the load on a subsequent step (in absorber ll) of the process.

It is necessary, then, to warm the base portion of this absorber since the solubilty of nitrogen a lower pressure but only at a sacrifice of absorptive capacity of the absorbent. This statement is true since the solubility of nitrogen in liquid sulfur dioxide is the reverse of the normal gasin-liquid solubilities, that is, nitrogen gas is less soluble in liquid sulfur dioxide at lower temperatures than at higher temperatures.

On account of the relatively high vapor pressure of liquid sulfur dioxide at my preferred operating temperatures, its evaporation is quite appreciable and accordingly the liquid absorbent is considerably cooled .by this evaporation. This cooling eflect is conducive to poor nitrogen absorption since, as mentioned above, at lower temperatures the solubility of nitrogen in this solvent is less. To maintain at an optimum the solvent power, a heating coil I1 is inserted at a point of maximum S02 evaporation. Thus by passing hot water or other mild heating agent through this coil temperature conditions are maintained at a favorable level.

This absorbed vessel I2 is, for the most part, of conventional design. It may be a bubble cap type vessel or a packed vessel or substantially any other type provided it is adapted to contact efficiently a gas and a liquid at the above mentioned pressure and temperature. The vessel must, of course, be constructed of materials which will not be corroded by gaseous or liquid sulfur dioxide even in the presence of traces or very small quantities of moisture.

In case the natural gas to be treated contains hydrogen sulfide, I can operate my process in such a manner as to remove this deleterious material. Under favorable conditions the following chemical reaction occurs:

This reaction takes place readily at about 100 F. in the presence of moisture. When the original gas is substantially dry or contains too little moisture for the efflcient oxidation of the hydrogen sulfide, I have provided a line i8 connected with the raw gas line inlet to the absorber whereby additional moisture can be added. The conversion of the hydrogen sulfide to free sulfur is accompanied by an equivalent amount of free sulfur from the sulfur dioxide. Sulfur from both sources then is carried in suspension in the liquid absorbent as finely divided free sulfur and I have made provision for the removal and utilization of this material.

The rich absorbent containing free sulfur in suspension is withdrawn from the base of the absorber through a line 2| and conducted to some auxiliary apparatus for removal of this sulfur. From line 2| this material passes to a sulfur removal means 22, such as a filter apparatus, centrifuge or settler. Since free sulfur is quite insoluble in liquid sulfur dioxide, the separation of the free sulfur by any suitable means is quite complete. From this separation means the illtrate or nitrogen containing absorbent passes by a line 23 to a drying or moisture removal unit while the separated sulfur passes by a conduit 28 to a drier 21 thence by another conduit 28 to a conversion means 3| wherein the free sulfur is converted or oxidized to sulfur dioxide. In this conversion stepnitrogen' (from air) remaining in the sulfur dioxide may, if desired, be permitted to remain thereimand themixture passed by a conduit 32, compressed by a pump 33, cooled and condensed, by a cooler 36 and finally passed into an accumulator vessel 31. Fromv this vessel liquid sulfur dioxide is passed through a line 38 to join the main lean absorbent stream in line ii. The gaseous nitrogen accumulating in this vessel 3'! obviously contains considerable uncondensed sulfur dioxide and this latter as well as the nitrogen may be reclaimed by passing this gas through line 1! to join the N2SO2' mixture in a, line I06, which mixture, is subsequently separated into a gaseous nitrogen by-product and sulfur dioxide for recycling into-the original absorber vessel I2,

7 which steps will be fully described hereinafter.

' this impurity is present in natural gas to the extent of several percent, in which case the sulfur dioxide obtained from such an amount is quite from its oxidation.

Water extracted from moist gas in the original absorption step and the moisture formed from the His-S02 reaction are best removed on account of a subsequent refrigeration step wherein the water freezes with resulting troubles. Substantially any water removing method may be used providing, ofcourse, it is suitable for the dehydration of liquid sulfur dioxide. .In case the moisture content is not excessively high, silica gel or other adsorbent driers may be used. When such are used two or more vessels may be used, while one is in dehydration service the second is on regeneration. However, in case the moisture content of the nitrogen laden absorbent is appreciable I prefer to use a liquid dehydrating agent such as ethylene glycol. Such a material as this is insoluble in liquid sulfur dioxide, insoluble or substantially so in hydrocarbons and also nonvolatile at water evaporation temperatures.

In the operation of this dehydrating step, I pass the sulfur dioxide absorbent rich in dissolved nitrogen and containing some dissolved moisture from line 23 into a contacting vessel 4| at a point near its top. This contacting vessel or dehydrator may be of substantially any desired design providing it permits intimate countercurrent contact between the two above mentioned liquids. Cool absorbent, such as the ethylene glycol enters this contacting vessel from a line 42 at a point near the bottom. These two liquid materials pass in c'ountercurrent relation to'each other since the glycol introduced at the bottom is specifically lighter than the liquid absorbent. The glycol agent with its acquired charge ofmoisture leaves the top of this contactor through a line 4'3 and passes therethrough to a stripper vessel 46. This stripper vessel contains a closed heating coil 41 in which steam or other heating agent passes in indirect heat exchange with the glycol. The temperature in the base of this vessel is maintained at such a value as to expel the dissolved moisture from the glycol so that the glycol material leaving the stripper and being cooled in cooler II will be in a fully revivified condition and rsadyfor additional contacting with sulfur dioxide ccntainingmoisture. Water in the one of steam leaves the stripper by the vapor line II for disposal as desired, while the temperature of the upper portion of this column must be sufiiciently high that the water therein is kept in the vapor islost as vapor with the overhead steam and at the same time dehydration is effective so that fully dry glycol'can bepassed to the SO: column.

, Exchanger or, heater 4 is installedin the wet glycol before it enters the stripper.

, market, providing it promotes efllcient water reappreciable as'is theamount of water formed moval.

The fully or substantially dry rich absorbent (liquid sulphur dioxide) leaves the dehydrator vessel H by line 52 and is passed through one or more coolers-represented by exchanger 53. Down to this point in absorbent flow the pressure has not been reduced under that carried in the original contactor l2 other than normal operating pressure drops on passage through pipes and treating vessels. This pressure has been maintained as stated and the temperature kept as nearly as possible to the original treating temperature in order to hold all nitrogen in solution with thesulfur dioxide. The pipe 52 carries a valve 56 which'may serve as a pressure reducing valve or just a valve for ordinary operational and safet purposes. I prefer to operate nitrogen stripper vessel 51 at about 700 pounds pressure the absorbent.

with said valve 5! substantially wide open. The rich absorbent enters the stripper vessel at a point near the top thereof and through a spray arrangement II. In this manner the absorbent is maintained in a state of violet agitation which assists materially in expelling the nitrogen from Since nitrogen is considerably less soluble at sub-zero temperatures than at atmospheric, I prefer to operate my N: stripper on a reversed temperature differential. that is, absorber temperature is about to F. and the stripper temperature carried to from about -30 F. to -60 F. At such-low temperatures the nitrogen is easily removed or stripped from the absorbent .even at a pressure of 700 pounds. As mentioned above, the cooler '53 imparts considerable cooling to the rich absorbent, for example, suillcient that the absorbent has a tempera-.

ture of about 10 to 15 F. Then upon entering the stripper through spray 58 some little S02 evaporation occurs imparting some additional cooling. The main cooling or chilling effect, however, is acquired from chilling coils ti which may be chilled by such a refrigerant as propane or ethylene or other systems. The source of this refrigeration may be of conventional design and well-known in the art and, for purposes of simplicity, is not shown on the drawing.

These refrigeration coils I are intended to chill the SO: absorbent to at least 30 F., at which temperaturethe solvent has little affinity that such temperatures are seldom used.

for the nitrogen gas. If desired, however, the stripper may be operated at a temperature approaching the freezing point of sulfur dioxide. At

such low temperatures, economic and mechanical difficulties present themselves to such an extent It is ordinaril more economical to circulate absorbent at a somewhat increased rate rather than to strip at extremely low temperatures. In view of this consideration, I prefer to maintain the chilling coil 6| at such a temperature that the liquid absorbent leaves the base of the stripper at about 25 to --30 F. At this temperature, substantially all of the nitrogen is expelled and the denuded absorbent leaves the stripper through a lean absorbent line 62 and passes in heat exchange relation with the rich absorbent (in line 52-) in exchanger 53. The lean absorbent is further warmed in an exchanger or heater 63 from which it passes by a line 66 to line l3 and on into the main absorber to complete the absorbent cycle.

Overall extracting of the nitrogen from the hydrocarbon gas is a function of the nitrogen content of the sulfur dioxide absorbent entering the absorber through line l3 when equilibrium is attained on the top absorber tray. Thus as long as some nitrogen is permitted to remain in the S02 lean absorbent all the nitrogen cannot beremoved from the natural gas. However, the solubility of nirogen in liquid S: is so small at 30 F. that approximately 97% of the nitrogen can be removed from th natural gas under equilibrium conditions in the top absorber tray.

Makeup'absorbent, if and when needed, may be added through a makeup S02 line 61. A pump 68 situated in line l3 serves to force transfer of the cyclic stream of sulfur dioxide into the main absorber against the absorber operating pressure of about 720 pounds per square inch. A liquid level controller apparatus IS in the base of the main absorber l2 serves to control the flow of rich absorbent from the absorber to the sulfur removal unit '22 by operations of a flow control valve 20. Similarly, liquid level controller 59 serves to control the flow of the denuded absorbent from the stripper by operation of a flow control valve 60 in line 62.

The warming agent entering exchanger 63 by a line 64 may be hot water, steam, or any other suitable agent as desired. A surge tank MI should be inserted in lin i3 preferably between the junction point of lines 65 and 61 and pump 68 to absorb fluctuations in liquid sulfur dioxide flow.

The main stripper of nitrogen stripper 51 is of unique construction and operation in that the top of the vessel is maintained at a higher temperature than is the base of the vessel. As mentioned above the incoming rich absorbent is at a temperature of about +10 to +15 F. while the reboiler section is kept at about -25 to -30 F. Thus in place of a heating coil in the base of tively great carryout is occasioned by the relatively high treating temperature of to F. maintained in the main absorber to effect as nearly complete removal of the nitrogen as possible. At 100 F. sulfur dioxide has a vapor pressure of approximately 43'? centimeters of mercury, which is 5% atmospheres or 86 pounds pressure per square inch. It is obvious that sulfur dioxide is undesirable in a fuel gas, it dilutes the .B. t. u. value, and then in case the gas is used for domestic purposes, open flames could not be tolerated.

In view of these above mentioned objections and many others, it ismost essential to remove this sulfur dioxide from the nitrogen free gas, and to reclaim it in such a manner that it may again be used as a nitrogen absorbent, either by itself or by recycling into the main 'SO: absorbent stream.

To remove the sulfur dioxide, I pass the hydrocarbon gas through an absorbent material which preferentially absorbs it, the reaction being reversed at an increased temperature for regeneration purposes. Such a material as I prefer to use is a liquid. amine, for example, diethylene triamine. This amine is a liquid and possesses the property of absorbing sulfur dioxide at atmospheric temperature or thereabouts and giving up or evolving the absorbed gas at a somewhat elevated temperature, thereby making possible a cyclic process.

To carry out this step, I pass the hydrocarbon gas containing sulfur dioxide gas, said mixture originating in the main N2 absorber, into the lower portion of a secondary absorber vessel II. This absorber may be of conventional absorber design but must be constructed to withstand an operating pressure equivalent to the pressure of the gaseous charge stock from line I6. The gas under said pressure, as about 700 pounds per inch, passes upward through this absorber in countercurrent relation to down flowing amine solvent. I have found that this contacting may be efficiently carried out at substantially atmospheric temperature, or about 90 F., this latter temperature being a preferred temperature. Treated hydrocarbons, substantially free from sulfur dioxide issues through a gas line 12 to disposal as desired or to further treatment. A line 13 leads lean amine absorbent into the upper portion of the absorber while enriched absorbent leaves .by a bottom line 15, the flow therethrough being regulated by a liquid level device I1 which operates a flow control valve 18 in line 16. The amine absorbent charged with the S02 passes from the outlet line 16 into another line 81, thence through a heat exchanger 82 and on through line 8| extended into the top portion of a stripper vessel 83. Fully regenerated amine absorbent passes from the base of said stripper by a line 86, through exchanger 82 and on by another line 81, through a cooler 88, another line 9| and finally into a surge tank I92, From this vessel amine passes by a bottom line I93 under suction from a pump I96 thence through line 13 into the sulfur dioxide absorber II to complete the amine cycle.

From the top of the S02 stripper vessel 83 the stripped gaseous S02 passes by an overhead line 92 through a cooler or partial condenser 93 into an accumulator 9B. A closed coil 90 permits passage of steam for reboiling purposes. I prefer to carry a reboiler temperature of about 275 F. and a top temperature of about F. To increase the efiiciency of this stripping operation at as low a temperature as possible, I use a hydrocarbon material as a sort of internal reflux. An

operation of this type is fully disclosed in an application for a patent, Serial No. 568,767, filed December 18, 1944, and now issued as Patent No. 2,404,854. ofwhich I am a coinventor. In this operation an inert hydrocarbon material is used to assist in stripping sulfur dioxide from a dihydrocarbon vapors at about 275 F. (substan-' tially fully vaporized) rise up the stripper and on condensing in the cooler rich absorbent impart heat of condensation which in turn heats the amine-SO: solution andassists in removal of the 802; The thus condensed hydrocarbon flows down the stripper and is again vaporized in the kettle thereof by reboiler coil 80 and the hot auavio column I! was described in conjunction with the continuous operation of the nitrogen removin cycle. This latter stripper removes nitrogen volume of nitrogen desorbed from the absorbent is relatively great. In order to reclaim this sulvapors again rise to condense and to liberate additional 80:. This operation is a type of internal refluxing. I operate this stripper at a pressure of from about 15 to 20 pounds per square inch absolute.

During this continuous and cyclic stripping operation, some of the hydrocarbon vapors are carried overhead from the stripper with the stream of evolved sulfur dioxide since the top stripper temperature is maintained at about 160 F. This stream of vapors, that is SO: and hydro- 1 carbons, pass from the stripper by the vapor linethrough the line 94 to assist in controlling temperature of the material in the accumulator 96. Makeup hydrocarbon fraction, when necessary, may be added to thesystem through an auxiliary line 99 from a source, not shown. 7

The particular hydrocarbon fraction which I have disclosed as the internal refluxing agent was taken merely as exemplary since the boiling point range may be varied considerably from that given and yet produce the same desired results. In case a higher boiling or lower boiling fraction is used,

the top stripper and reboiler temperatures are adjusted accordingly. Similarly the operation of heater IOI is so adjusted that the hydrocarbon is substantially fully vaporized so that only vapors may be passed into the base of the stripper.

Sufllcient-heat should be added to the hydrocarbon refluxing material by heater [Ill and reboiler coil 90 that liquid hydrocarbon is not or substantially not permitted to remain in the amine stripper bottoms, so that only active amine 1 will be passed from the stripper to the absorber I i This amine-SO: stripping step has been described as a portion of the absorber Ii-stripper 83 cycle which continuously removes $0: from the nitrogen-free hydrocarbon gas from the original or primary absorber ii. A stripper gas from the rich sulfur dioxide absorbent coming from absorber II. The nitrogen issuing through a line I" also carries a quantity of sulfur dioxide vapors, the proportion of which is a function of the stripper (ll) temperature and pressure. While this proportion of S0: is not especially great on account oi the low temperature carried in stripper 51, yet the quantity passing out is considerable per unit of time since the fur dioxide. I provide an'auxiliary absorber I01 wherein the sulfur dioxide laden nitrogen may be stripped of its sulfur dioxide thereby serving the double purpose of preparing a nearly pure stream of nitrogen and saving sulfur dioxide for solvent cycling purposes. A portion of the diethylene triamine absorbent stream passing through line 81 is by passed from the main line ll to flow through a pipe I" into the top of the auxiliary SO: absorber. This absorber is practicallythe same in constructional and operational details as the main SO: absorber 1|. main diiference is in operation in that is removed from a nitrogen containing stream in place of from a hydrocarbon. stream. The nitrogen and sulfur dioxide stream passes from the stripper 51 at a pressure of about 700 pounds andenters absorber III! at about the same pressure. Lean amine absorbent entering from line is transferred and pressured by a pump I09. The amine and N2SO: streams flow through their contactor in a countercurrent manner, the treated gas, that is nitrogen substantially free o! 80:, emerges through a gas line III while the S0: laden amine passes therefrom through a rich absorbent line III; This latter stream joins the rich amine stream from absorber 1i and the combined stream passes through the line 8|, and exchanger 82 into the SOP-amine stripper 83. Thus it is seen that the two 80: absorbers II and Ill receive lean absorbent from the one 80:

amine stripper 83.

As mentioned above the absorber I01 is operated at a pressure of about 700 pounds per square inch pressure, the exact temperature being less important- The lean amine on passing through the cooler 88 issues therefrom at a temperature of about 90 1"., thus that is also the lean absorbent inlet temperature in the absorber I01. The N's-80: stream flowing into this absorber base may be at stripper 5'! temperature which is -25 to -30 F., or if desired it may be warmed somewhat through a heat exchanger in case some cooling of another stream is desired. this heat exchanger isnot shown on drawing for purposes of simplicity.

The nitrogen gas issuing from the SO: absorber I01 is substantially free of sulfur dioxide, but I have found that it sometimes contains traces of hydrocarbon. Since the presence of even a trace of hydrocarbon in a commercial nitrogen product isundesirable, I herein make provision for removal for same. The impure nitrogen stream passes from the absorber llll through line I l l into an adsorber vessel H3. In this vessel is such an adsorbent material as activated charcoal or such other'ac'tive material as will eflectively adsorb hydrocarbons. I have found in the practice of my invention that the nitrogen stream contains from to 99% of this gas with the remainder being largely such hydrocarbons as methane,

ethane and even some propane. Activated charcoal effectively removes such hydrocarbons. It will be obvious that after some time on stream, the adsorbent will become fully charged or saturated with these hydrocarbons and must be taken ofi stream for regeneration purposes. Thus a standby adsorber, previously regenerated, is put onstream and the saturated one then may be steamed for reactivation of the charcoal and recovery of the hydrocarbons, if desired. Only one adsorbent vessel is shown, for purposes of simplicity, but it is to be understood that as many vessels may be used as necessary.

As an alternative nitrogen purification step, this vessel II3 may'represent diagrammatically a mineral seal oil absorption unit such as might be used in natural gasoline extraction plants. In this alternative method, the absorption unit will' consist of an absorber and a stripper and such other parts as pumps, meters, etc., as may be needed to carry out effectively the removal of the small amount of hydrocarbon from the nitrogen.

From either of these alternative purification methods, purified nitrogen gas issues by a line H6 for disposal as desired. Likewise, from either unit, the recovered hydrocarbon may be added to the main hydrocarbon product line or disposed of otherwise as desired, such disposal has not been shown on the drawing.

The main hydrocarbon stream, free from nitrogen and issuingfrom the top of the S02 absorber II may at times contain traces of sulfur dioxide gas. A vessel II'I represents diagrammatically an adsorption unit charged with an activated bauxite adsorbent or other adsorbent material suitable for the separation of traces of sulfur dioxide from hydrocarbon gases. The hydrocarbon gas passes from the absorber 'II through the overhead gas line 12 into the bauxite adsorption unit 1, the treated gas passing out through a final product line II8 to a pipeline for transportation or to intermediate storage, or other disposal as desired.

This bauxite adsorption unit may well be composed of at least two vessels containing adsorbent so that when one is on stream the other is being revivified for subsequent use, The revivification may be by passage of steam through the catalyst bed or by any other method as desired. Only one vessel, identified by numeral III, is shown in the drawing but the complete unit is intended.

As mentioned hereinbefore, the SO2amine .stripper tower 83 removes sulfur dioxide gas from the amine, the gas passing from the stripper. through the overhead gas line 02, The use of a hydrocarbon internal refluxing agent in this stripping operation was also described. This refluxing agent is of such a boiling range that carryover in the effluent gas is condensed in condenser 93, the condensate accumulating in vessel 06. This condenser is so operated that the sulfur dioxide remains in the gaseous form and it may be withdrawn from the accumulator vessel 98 through line I02 for such recycle purposes as desired. I have found that the sulfur dioxde gas withdrawn in this line I02 contains some hydrocarbon material not included in the boiling range of the internal refluxing material. Since the sulfur dioxide should for the most part be recycled into the original absorption step, any hydrocarbon contained therein should preferably be removed previous to the recycling.

To remove such hydrocarbon the sulfur dioxide stream passing through line I02 is compressed by a pump I03 and transferred through line III and condenser I 22 into accumulator vessel I23. The pressure imposed by this pump is such that sulfur dioxide and some hydrocarbons are condensed in condenser I22. Thus the relatively heavy liquid SO: settles to the bottom and the liquid hydrocarbon as an upper layer in the accumulator I23. Uncondensed hydrocarbon such as methane, ethane and propane are removed through a gas line I28 and disposed of as desired, for example they may be added to the nitrogen-free ei'lluent gas passing from absorber II through line 12 to adsorber I. On passing through the adsorber III any remaining sulfur dioxide is removed and this added hydrocarbon as tends to bolster the B. t. 11. content of the final plant eilluent gas.

The liquid or condensed hydrocarbons may be withdrawn from the separator I23 by a line I21 and disposed of as desired while the liquid sulfur dioxide is withdrawn through a line I20 and passed by another line IlI into the main plant inlet gas line II and finally into the primary absorber vessel.

when treating a relatively dry natural gas by this process, little condensible hydrocarbon will issue with the sulfur dioxide from accumulator 08 and the step of condensing this eilluent gas for separation of condensible hydrocarbons may be omitted. In such a case, it is desirable to pass the sulfur dioxide with its very small quantity of uncondensi-ble hydrocarbon from the separator 00 through pipe I02 into compressor I03. This compressor furnishes sufficient pressure 'to force the SO: through a bypass line I 32 into the line III and finally into the main plant gas inlet line II. This gaseous sulfur dioxide recycled in this manner serves several purposes, first, sulfur dioxide is saved thereby reducing SO: chemical costs; and second, gaseous S02 is added to the incoming hydrocarbon gas thereby at least partly saturating this gas so that less SO: will be evaporated from the body of-liquid solventvduring passage of the hydrocarbon gas through the liquid sulfur dioxide in absorber I2. This pre-saturation of gas is especially desirable since evaporation of SO: in the primary absorber materially cools the S02 solvent and, in so doing, decreases the solubility of nitrogen gas in said solvent.

The solution or dissolving of nitrogen gas in liquid sulfur dioxide is apparently endothermic and tends to cool the solvent in the primary absorber I 2. Cooling from this cause when added to cooling from S0: evaporation very materially decreases the solubility of N2 in liquid S02, and under such. conditions the rate of absorbent (liquid S02) circulation must be materially increased in order to absorb completely the nitrogen. By recycling the gaseous SO: from the accumulator by lines I02, I 32, and I3I into the original gas line I I, I am able to prevent a large part of said deleterious cooling of the absorbent S02, while coil I I is intended to furnish sufllcient heat to maintain constant the desired absorption temperature. Line I3I may preferably contain a drier I40, of suitable design, to dry the recycle SO: in case hydrocarbon gases being treated are dry and it is desired to prevent entrance of moisture in the absorber I2.

In the above discussion of the SO: absorption step in absorber columns II and I01, the use of diethylene triamine absorbent was described. It is possible to use other amines such as diethanol amine, or even still other amines providing they possess such, properties as will permit their use for the-purpose at hand.

In addition, the diethylene triamine may be mixed with some glycol and the mixture used in a manner similar to the triamine alone. The mixture in additionto absorption of S02 also removes moisture from the material being treated so that the treated material isifree ofacidic gas and dry from moisture. Since this glycol has a great afflnity for water, as much as or even more water may'bepermitted to accumulate in the diethylene triamine-glycol absorbent solution 4 and yet act as an eilicient drying agent. If desired, such an absorbent solution may even contain this 10% water at the start of operations.

In my aforegiven discussionrelative to B. t. 11.

contents, nitrogen contents, etc., I mentioned that.

removal-ofnitrogen permitted extraction of appreciable quantities of high B. t. u. natural gasoline hydrocarbons. Thus the final nitrogen-free gas issuing from my process by pipe I It may. be passed to a conventional gasoline extraction plant. The operationof such a plant should be to maintain a constant anddesiredB. t. u. content of efliuent dry gas, for example, if usersv desire a 1000 B. t. u. gas, then the extraction plant 'i'nay be operated to produce a gas of 1005 or 1010 B. t. u.

per cubic foot, or other 3. t.- u. content asdesired.

Said gasoline plant may, obviously, precede'my nitrogen removal plant as well asgfoilow it.

The operation of the primary N2. absorber l2 and the SO: absorber ll were hereinbefor'e described as carried out at-about. 720 pounds per square inch absolute pressure, whichmight, however, be as low as 500 poundsor as high as 1000 pounds and yet function according to my invention. I do not wish to limit such operation to thesepressures since still my invention-1 may. be

tration, if a natural gas contains say 15% by volume of nitrogen and 1% by volume of helium,

upon removal of all those inert gases, then same will contain 15 parts N2 to 1 part He which will be over.6% by volume of helium. Such a source of helium would be a valuable one in case large quantities of such natural gas are treated.

In the appended claims the term nitrogen is intended to include nitrogen gas alone or a mixture of nitrogen gas and helium gas, the nitrogen usually being present in a relatively large proportion as compared to the helium. Nitrogen is intended also to include other inert gases, like argon.

In the above description many minor pieces of equipment have not been mentioned, nor shown.

on the drawing for purposes of simplicity. For example, many valves, temperature measuring and/or recording devices, flow controllers, level controllers. pressure controllers and/or' recorders, and many other pieces of apparatus, the operation and'use of which are well-known to those skilled in such art, are omitted. Most of the apparatus used in the practice of my invention may be of standard design and made of standard materials, but where special apparatus is needed. such is contemplated.

While substantially one-set of operating. conditions are described for exemplary purposes, it will be understood by those skilled in the art that such conditions may be varied within wide practiced at still higher pressures. For example,

I contemplate the use of my invention in recycle or distillate fields-wherein the natural gas coming from the well or frame field separator. may

have a pressure as lugh'as .3000 or 400. or ,even more pounds per square inch.- V

. In the above description of an illustrative embodiment of my invention," the purificationpf natinal gas was discussed. However," it is 'o b-" vious that the usual artificial'fuel gaasuchQ-las water gas, producer gas, blau gas and 'othersmay be improved "by .the same. process. These gases generally consist of hydrogen, :nitrogen,

arbon monoxide and some hydrocarbons-and ti s of;

argon. The nitrogen and probably the argon arev the only ones of these gases soluble in the sulfur dioxide under the conditions'in tower l2. asset forth above.

The carbon monoxide and hydrogen are substantially insoluble in sulfur dioxide and otherwise'react in the system substantially as the hydrocarbon elements did in the natural gas as outlined above, and thus pass through the system in the same manner, entering the system at II and leavingthrough pipe H8.

Some natural gases contain the rare gas helium. In case such a gas as contemplated for treatment as herein described contains helium gas along with nitrogen, my invention serves then a double purpose. In" addition toremoval of the inert, noncombustible nitrogen from the gas, helium is also removed. This step is possible since helium gas is soluble in liquid sulfur dioxide. In addition it is more soluble in the sulfur dioxide absorbent at my absorber temperature of 90 to 100 F. than it is at the stripper temperature ofabout 30 F. As an illuslimits and yet remain within the intended spirit and scope of my invention.

Having disclosed my invention. I claim: v v 1. A process for'removing nitrogen gas from fuel gas containing the same comprising the .steps of contacting the fuel gas with liquid sulfur dioxide at a temperature remote from and above the melting point of sulfur dioxide and separat ing the contacted fuel gas from the sulfur dioxide liquid.

' 2. A process-for removing nitrogen gas from a gaseous mixture -'containing hydrocarbon and nitrogen comprising the steps of contacting the gaseous mixture with liquid sulfur dioxide at a contacting temperature but above the melting ide wherein the nitrogen passes into solution in point of sulfur dioxide and recycling the solvent into the contacting step, at the contacting temperature and removing the contacted gas.

4. A continous process for removing, gaseous nitrogen from hydrocarbon gas containing same comprising contacting the gas with a solvent of liquid sulfur dioxide at a temperature remote from and above the melting point of sulfur dioxthe sulfur dioxide, separating the contacted gas as nitrogen free gas from the solvent containing the nitrogen, separating the nitrogen from said solvent at a temperature below said contacting temperature but above the melting point of sulfur dioxide and recycling the denuded solvent into the original contacting step, removing the nitrogen-free gas, as the primary product of the process, and removing the separated nitrogen as a secondary product of the process.

5. A continuous process for upgrading the heating value of a natural gas containing gaseous nitrogen comprising the steps of contacting the natural gas containing nitrogen with liquid sulfur dioxide at a temperature remote from and above the freezing point of sulfur dioxide, whereby the nitrogen passes into the liquid sulfur dioxide and some sulfur dioxide vaporizes into the natural gas, separating the liquid sulfur dioxide from the natural gas, separating the nitrogen from the liquid sulfur dioxide at a temperature below said contacting temperature but above the freezing point of sulfur dioxide, and removing the nitrogen as a secondary product of the process, separating the sulfur dioxide vapor from the natural gas and removing the latter as the primary product of the process having an improved heating value.

6. A continuous process for upgrading the heating value of a natural gas containing inert nitrogen comprising the steps of contacting said natural gas with liquid sulfur dioxide at a temperature remote from but above the freezing point of sulfur dioxide, separating the natural gas containing vaporous sulfur dioxide from the liquid sulfur dioxide containing nitrogen; contacting the natural gas containing vaporous sulfur dioxide with an amine absorbent, separating the finally contacted natural gas from the amine absorbent and removing same as the natural gas of upgraded heating value.

'7. A continuous process for upgrading the heating value of a natural gas containing inert nitrogen comprising the steps of contacting said natural gas with liquid sulfur dioxide at a temperature remote from but above the freezing point of sulfur dioxide, separating the natural gas containing vaporous sulfur dioxide from the liquid sulfur dioxide solvent containing nitrogen; contacting the natural gas containing vaporous sulfur dioxide with diethylene triamine, separating the finally contacted natural gas from the amine and removing the gas as the natural gas of upgraded heating value.

8. A continuous process for upgrading the heating value of a natural gas containing gaseous nitrogen comprising the steps of contacting the natural gas containing nitrogen with liquid sulfur dioxide at a temperature remote from but above the freezing point of the sulfur dioxide whereby the nitrogen passes into the liquid sulfur dioxide and some sulfur dioxide vaporizes into the natural gas, separating the liquid sulfur dioxide from the so contacted natural gas,

separating the nitrogen from the liquid sulfur dioxide at a temperature below said contacting temperature but above the freezing point of the sulfur dioxide and recycling the latter into the original contacting step and removing the nitrogen as a secondary product of the process; separating the sulfur dioxide vapor from the contacted natural gas, recycling the so separated sulfur dioxide into the original contacting step at said contacting temperature and removing the latter natural gas as the primary product of the process.

9. A continuous process for upgrading the heating value of a natural gas containing gaseous nitrogen comprising the steps of contacting the natural gas containing nitrogen with liquid sulfur dioxide at a temperature remote from but above the freezing point of the sulfur dioxide whereby the nitrogen passes into the liquid sul- 16 fur dioxide and some sulfur dioxide vaporizes into the natural gas, separating the liquid sulfur dioxide from the so contacted natural gas, separating the nitrogen from the liquid sulfur dioxide at a temperature below said contacting temperature but above the freezing point of the sulfur dioxide and recycling the latter into the original contacting step and removing the nitro gen as a secondary product of the process; contacting the so treated natural gas containing sulfur dioxide vapor with diethylene triamine,

separating the finally contacted natural gas from the amine and removing said gas as the natural gas of upgraded heating value and primary product of the process, treating the latter amine for removal of absorbed sulfur dioxide and separating the amine from said sulfur dioxide, recycling the amine into the original diethylene triamine and recycling the sulfur dioxide into the original contacting steps.

10. A continuous process for upgrading the heating value of a natural gas containing noncombustible nitrogen gas comprising the steps of contacting said natural gas with liquid sulfur dioxide at super-atmospheric pressure and at substantially atmospheric temperature whereby the nitrogen passes into the liquid sulfur dioxide and some sulfur dioxide vaporizes into the natural gas, separating the liquid sulfur dioxide from the natural gas containing vaporous sulfur dioxide, separating the nitrogen from the liquid sulfur dioxide at a sub-atmospheric temperature, and removing the nitrogen as a secondary product of the process, and recycling the latter sulfur dioxide into the original contacting step at substantially atmospheric temperature and at super-atmospheric pressure; separating the sulfur dioxide vapor from the contaced natural gas and removing the latter as the pr mary product of the process and recycling this separated sulfur dioxide into the original contacting step at substantially atmospheric temperature and super-atmospheric pressure,

11. A continuous process for upgrading the heating value of a natural gas containing noncombustible nitrogen gas comprising the steps of contacting said natural gas with liquid sulfur dioxide at superatmospheric pressure and at substantially atmospheric temperature whereby the nitrogen passes into the liquid sulfur dioxide and some sulfur dioxide vaporizes into the natural gas, separating the liquid sulfur dioxide from the natural gas containing vaporous sulfur dioxide, separating the nitrogen from the liquid sulfur dioxide at a subatmospheric temperature, and removing the nitrogen as a secondary product of the process, and recycling the latter sulfur dioxide into the original contacting step at substantially atmospheric temperature and at superatmospheric pressure; contacting the so treated natural gas containing sulfur dioxide vapors with diethylene triamine at essentially atmospheric temperature and at superatmospheric pressure wherein the sulfur dioxide vapors become absorbed-in the diethylene triamine, separating the finally contacted natural gas from the amine and removing said gas as the natural gas of upgraded heating value and primary product of the process: treating the latter amine at a superatmospheric temperature for removal of absorbed sulfur dioxide, separating said sulfur dioxide from the amine and recycling the amine into first said diethylene triamine at essentially atmospheric temperature and at superatmospheric pressure, and recycling said latter separated sul- 17 fur dioxide into the original contacting step at essentially atmospheric temperature and at superatmospheric pressure.

12. The process of claim 11 wherein the absorbed sulfur dioxide is removed from the diethylene triamine by a stripping operation employing as an internal refluxing agent a paraffinic hydrocarbon fraction boiling from about 160 to 275 F.

13. The process of claim 11 wherein the absorbed sulfur dioxide is removed from the diethylene triamine by a stripping operation employing as an internal refluxing agent a paraflinic hydrocarbon fraction boiling from about 160 to 275-and wherein this removed sulfur dioxide is recycled into the original natural gas containing noncombustible nitrogen gas to minimize evaporation of liquid sulfur dioxide in the natural gas being treated in the original contacting step.

14. The process of claim 11 wherein the nitrogen separated from the liquid sulfur dioxide at a sub-atmospheric temperature is contacted with diethylene triamine at approximately atmospheric temperature whereby the nitrogen is substantially freed of sulfur dioxide vapors and the nitrogen is removed as the substantially pure nitrogen and secondary product of the process, and heating the contacted diethylene triamine to a temperature above atmospheric temperature to liberate the absorbed sulfur dioxide, and recycling said sulfur dioxide into the original contacting step.

15. The process of claim 11 wherein the nitrogen separated from the liquid sulfur dioxide at a sub-atmospheric temperature is contacted with diethylene triamine whereby the nitrogen is substantially freed of sulfur dioxide vapors, and recycling said sulfur dioxide into the original contacting step, further treating said nitrogen by contacting with an adsorbent' for removal of traces of hydrocarbon to produce a highly purified nitrogen as the secondary product of the process and removing same as said product; and further treating said upgraded natural gas by 18 contacting with an adsorbent for removal of final ,traces of sulfur dioxide and removing this so treated gas as a highly purified, upgraded heating value natural gas primary product of the process.

16. The process of claim 11 wherein the origi- .nal nitrogen containing gas contains hydrogen sulfide and moisture, and the original contactin step is carried out at a temperature of about F. wherein the hydrogen sulfide is oxidized to free sulfur and water, and the nitrogen and free sulfur laden liquid sulfur dioxide removed from point of sulfur dioxide and removing the so treated gaseous hydrocarbons from the sulfur dioxide substantiallyv free of nitrogen and hydrogen sulfide, and removing said hydrocarbons. JOHN W. LATCHUM, JR.

REFERENCES CITED The following references are of record in the file of this patent:

UNITED STATES PATENTS Name Date Clark Aug. 23, 1938 Voorhees Apr. 9, 1040 FOREIGN PATENTS Country Date Great Britain 1881 Number 2,128,027 2,196,281

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